June 2013 Getting gas right Australia’s energy challenge Tony Wood and Lucy Carter The housing we’d choose Getting gas right: Australia’s energy challenge

Grattan Institute Support Grattan Institute Report No. 2013-6, June 2013 This report was written by Tony Wood, Grattan Institute Energy Program Director and Lucy Carter, Energy Fellow. Daniel Mullerworth and James Button provided extensive research assistance and made substantial contributions to the report.

We would like to thank the members of Grattan Institute’s Energy Reference Group for their helpful comments, as well as numerous industry participants and officials for their input.

The opinions in this report are those of the authors and do not necessarily represent the views of Grattan Institute’s founding members, affiliates, individual board members or reference group members. Any remaining errors or omissions are the responsibility of the authors.

Grattan Institute is an independent think-tank focused on Australian public policy. Our work is independent, practical and rigorous. We aim to improve policy outcomes by engaging with both decision-makers and the community.

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This report may be cited as: Wood, T. Carter, L., and Mullerworth, D., 2013, Getting gas right: Australia’s energy challenge, Grattan Institute ISBN: 978-1-925015-40-9 All material published or otherwise created by Grattan Institute is licensed under a Creative Commons Attribution-NonCommercial-ShareAlike 3.0 Unported License

Grattan Institute 2013 Getting gas right: Australia’s energy challenge

Overview

Next year the first liquefied natural gas (LNG) carrier ships will market. Western Australia should go further, and end its policy of dock off Gladstone in Queensland, ready to ship LNG to Asian reserving gas for domestic use. Protectionism may provide some and other markets. By 2017 east coast gas, added to growing short-term price relief for targeted industries, but ultimately it leads Western Australian supplies, could create the world’s biggest gas to higher prices and damages the economy. export industry, worth $53 billion a year. But this transformation is not good news for everyone. Yet government and industry both have vital roles in ensuring the market works efficiently. Governments must: Strong Asian demand and high prices are inducing Australian producers to export their gas. That means local consumers will • Resolve the coal seam gas impasse in New South Wales. have to pay higher prices. Within the next couple of years, gas prices for households on the east coast, particularly in Victoria, • Create a more transparent gas market that includes new will rise by as much as $170 a year. Large industrial users of gas trading hubs, such as Wallumbilla in Queensland, and a will come under pressure from equally significant price increases. gas price index that provides clear information to all players. Gas presents other challenges, too. Infrastructure constraints plus commercial battles over prices mean there may be difficulties • Remove barriers to efficient supply by freeing up trading of getting gas to where it is needed on the east coast, especially in pipeline capacity, and moving towards elimination of joint New South Wales. And the long-anticipated ‘dash for gas’, in marketing arrangements as the market matures. which it acts as a transition fuel while electricity generation shifts over time from coal to low-carbon technologies, is not happening Industry, for its part, must ensure supply can flow. There is no in Australia. Falling demand, rising gas prices and a renewable shortage of gas, but infrastructure may be physically unable to energy target that largely supports new wind energy mean new meet growing demand in the short term. Gas producers must gas-fired electricity generation is unlikely to be required for at respond to the needs of their customers or political pressure will least the next decade. push governments to intervene.

With more than $160 billion forecast to be invested in LNG With global gas resources likely to last at least 200 years, the production, the export industry is good for the economy. International Energy Agency has described the next decade as Governments should therefore resist self-interested calls from the ‘golden age of gas’. Australia is well placed to reap the some industries to cap prices or reserve gas for the domestic commercial benefits, but has further to go to create an affordable, reliable and sustainable energy sector.

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Table of contents

1. What does the global gas revolution mean for Australia? ...... 4

2. How should government and industry respond? ...... 15

3. Gas on the east coast ...... 25

4. The West Australian gas market ...... 32

5. Carbon emissions and gas-fired power generation ...... 40

6. References ...... 45

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1. What does the global gas revolution mean for Australia?

1.1 Gas markets are on the move Australia has an unparalleled opportunity to exploit its vast gas reserves and access to major markets in Japan, Korea, China and Around the world, gas markets are changing on an India. By 2015, Australia is projected to be the world’s second unprecedented scale. Demand is surging. Between 1990 and largest LNG exporter, after Qatar (see Box 1 for a description of 2010 gas consumption increased by 63 per cent. By 2020 it is LNG).3 By 2017 it may be the largest.4 But what is good news for forecast to have nearly doubled since 1990.1 exporters is not necessarily good for local consumers of gas.

A number of developments are driving demand for gas: 1.2 Supply has rapidly emerged to meet the market

• Worldwide demand for energy is growing due to rapid Current assessments of global gas resources exceed 200 years economic development in China, India, and the Middle East.2 of supply at current levels of production.5 The ‘game-changer’, as the United States Energy Information Administration (EIA) called • Global supplies are growing, and are more than enough to it, has been the invention of affordable ways to extract shale gas. meet demand. Increased supply pushes down the price. Shale gas is a standard form of gas but is extracted from a different type of rock under the earth’s surface. Innovative drilling • Several countries have banned or restricted the use of nuclear techniques have made it possible to extract this gas at affordable power following the Japanese nuclear disaster in 2011. prices. There is also a lot of it.

• Concerns about climate change mean that companies and Figure 1 shows how shale gas production - virtually non-existent a nations need to limit emissions of carbon dioxide. Gas power decade ago - is projected to dominate US gas production by plants are usually cheaper than renewable power generators 2040. This chart also reflects how new supply was developed to such as solar and wind. Gas produces fewer carbon meet higher demand and higher prices. The techniques emissions than coal and does not have the waste disposal problems of nuclear energy.

3 BREE (2012c) 1 From 76 exajoules to 147 exajoules per year. IEA (2012) 4 Bethune (2013) 2 Ibid. 5 IEA (2012)

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developed in the US have the potential to be applied more widely. Figure 1: US natural gas prices and production, 1990 to 2040 While producers face challenges to extract gas from new locations using these new techniques, supplies have the potential to last a long time.

Box 1: What is LNG? What is an LNG train?

In domestic markets, gas is typically transported through pipelines. But when gas needs to be transported overseas it may not be technically viable or economically attractive to build a pipeline. In this case, gas must be transported by ship.

Liquefied natural gas or LNG is produced because it is more efficient to transport than natural gas. The LNG is created by passing gas through a system called an LNG train, which cools and compresses the gas, then loads it onto a ship for transport.

When LNG arrives at its destination, it is regasified – turned back into gas - and then delivered to end users through domestic pipelines. Converting gas to LNG, transporting it and regasifying it Source: EIA (2012); EIA (2013b); EIA (2013a) on arrival is expensive. To liquefy and ship it from Australia to Asia may cost $5 to $6 a gigajoule, more than the cost of gas in As shown in Table 1, Australia’s ‘proven and probable’ reserves of many Australian markets today. coal seam gas and conventional gas are around 140,000 petajoules, enough to meet more than 70 years of gas demand at current rates of production. 6 The potential in-ground Coal seam gas and shale gas are often grouped under the resource of coal seam and shale gas could be four times as large heading ‘unconventional gas’ as described in Box 2. as known reserves.7 A recent report for the Australian Council of Learned Academies describes the shale potential in Australia,

6 EnergyQuest (2012) cited in AER (2012) 7 BREE (2012c)

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whilst also indicating that it may not be as readily realised as it Figure 2: Global gas prices for key regions has been in the USA.8 US$ per gigajoule Table 1: Australia’s ‘proven and probable’ gas reserves and 20 production, 2012 18

Market Type Reserves Production 16 Japan (petajoules) (petajoules) 14 Western Australia Conventional 89,900 1,193 Europe 12 Northern Territory Conventional 1,300 33 East Coast Conventional 7,100 453 10 East Coast Coal seam gas 41,700 247 8 Total 140,000 1,924 6 Notes: Totals may not add due to rounding. Production includes both domestic sales and exports. 4 USA Source: EnergyQuest (2012), as cited in AER (2012) 2 1.3 Rising demand expands the Australian industry 0 2000 2002 2004 2006 2008 2010 2012 High gas prices in Asia, as shown in Figure 2, have supported enormous investment in infrastructure in Australia, despite its high Source: World Bank (2013) construction costs relative to other countries. This investment of over $160 billion will pay for the 13 new LNG On the east coast, $50 billion has been committed to developing trains currently under construction on Australia’s east and west LNG export facilities based on coal seam gas in Queensland. In coasts. A further 19 trains are in the planning stage for possible Western Australia, over $116 billion is being spent on projects development. The LNG industry is set to become a driving force under construction to expand the LNG export industry. Figure 3 for jobs and growth in the economy over the next decade and shows forecast demand for east coast gas over the next two beyond. decades.

8 Australian Council of Learned Academies (2013)

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Box 2: What is 'unconventional' gas? Shale gas and tight gas are extracted from layers of rock Imagine trying to get all of the air out of a hollow chocolate with low permeability (small gas bubbles), which prevents Easter egg. Now, imagine trying to get the air out of a chocolate gas collecting in a reservoir. Shale gas is found in Aero bar, where it is trapped in small bubbles between the sedimentary rocks such as sandstone. Tight gas is found in chocolate. The analogy illustrates the differences between denser types of rock. extracting gas from conventional and from unconventional gas Australia is a world leader in coal seam gas technology and reservoirs. production but development of shale and tight gas ‘Conventional’ gas is extracted from a large underground resources remain in their infancy. chamber - like an Easter egg. The gas filters upwards through Conventional and unconventional gas wells both produce layers of porous sandstone deep in the earth’s crust until it is the same product – methane or ‘natural gas’. trapped under a dense layer of ‘impermeable’ rock. To extract the gas, a hole is drilled to the highest point in the reservoir and gas, which is lighter than air, flows to the surface.

Unconventional gas, like the air in an Aero bar, is not found in a continuous underground chamber. To encourage gas to flow from an unconventional well, producers sometimes inject fluid into the gas reservoir to fracture the rock and encourage gas flow. This technique is called hydraulic fracturing or ‘fracking’. Its critics say that fracturing the rock may allow gas or chemicals to enter ground water supplies.

Unconventional gas supplies fall into several categories.

Coal seam gas (CSG) is extracted from coal deposits. The gas is released by extracting water from around the coal deposit. Removing the water reduces pressure and releases the gas.

Source: Grattan analysis

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Figure 3: Forecast gas demand for eastern and Western Australia, 1.4 The price of going global 2010 to 2030 Petajoules per year Until now, Australia’s east coast gas market and the global gas 7,000 market have been physically disconnected. As such, there has been no way for gas sellers to move gas from lower-priced 6,000 domestic markets to higher-priced international markets. This has allowed different gas prices to develop in each market. From next year, LNG exports will commence from the east coast and the two 5,000 West Coast Export markets will be connected for the first time. That will bring their prices together, and lift prices at home. Sellers, attracted by 4,000 higher prices, will move supply from the cheaper to the more expensive market until prices converge. 3,000 East Coast Export At present, Japanese buyers are prepared to pay about $15 a 2,000 gigajoule. While Australian gas prices are forecast to rise, it is West Coast highly unlikely that domestic gas prices will rise to the same level 1,000 Domestic as the prices seen in Japan. The gas price in importing countries East Coast includes the cost for converting gas to LNG, transporting it by ship 0 Domestic and converting back to gas on arrival. The process is expensive – 2010 2014 2018 2022 2026 2030 in the range of $5 to $6 a gigajoule to send gas from Australia to Source: AEMO (2012a); ACIL Tasman (2011); Government of Western Australia (2012a) Japan. This cost differential provides an advantage for businesses buying gas in a country with gas reserves relative to competitors The domestic gas industry will also gain from production in countries that have to import their gas. economies of scale, which bring down the cost of extracting unconventional gas such as coal seam or shale gas. Australian This ‘export parity’ price is therefore setting the benchmark for markets are also unlikely to suffer the fate of US markets, where new gas contract negotiations in Australia. Because east coast gas users faced several years of shortages and high prices before gas prices have not been exposed to international markets, producers made breakthroughs in developing unconventional gas. domestic wholesale contract prices have been both stable and In Australia, export opportunities are driving these breakthroughs. low by international standards - about $3 to $4 a gigajoule.9 Underlying low costs of production plus the need to compete with Yet this good news for the Australian economy also carries a price. 9 AER (2012)

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coal and oil for electricity and industry have also kept prices low. that may be expected by 2020, the transition to higher prices may But when exports start, prices are likely to rise. At the same time, not be gradual. It is possible that prices will rise sharply over the the production cost of new gas sources is also expected to rise. next few years as exports commence on the east coast and are expanded on the west, then increase only moderately before In Western Australia, which already exports LNG in large 2020. volumes, prices are around $5.40 a gigajoule. The expected price increases will follow major increases in Over the next several years, wholesale domestic gas price electricity prices over the last several years. They will be felt most increases of more than 80 per cent nationally can be expected. acutely by residential customers and some parts of the Table 2 shows ‘base case’ gas price forecasts from a number of manufacturing industry. analysts of Australia’s east and west coast markets. 1.4.1 Gas use in Australia Table 2: Analysts’ gas price forecasts for the east and west coasts of Australia (real $ a gigajoule, $2012-13) Gas is a major source of energy in Australia. Gas provided 20 per cent of all final energy consumption in the Australian economy in Source Forecast Eastern Market Western Market year 2010-11, with the balance coming from oil (52 per cent), electricity 2020 2030 2020 2030 (21 per cent), coal (4 per cent) and renewable energy (4 per ACIL Tasman 2010 6.6 7.9 8.0 8.4 cent).10 ACIL Tasman 2011 7.9 10.6 - - ACIL Tasman 2012 8.6 11.7 13.4 11.8 A third of the gas used in the domestic economy is used for AEMO/IES 2011 7.0 8.3 - - supplying electricity, as shown in Figure 4. Another sixth is used in other energy transformations, where gas is used to refine other Australian Treasury 2011 - 10.1 - 10.1 (ROAM) fuels, such as coal or petroleum. This is one of the reasons why the significant role of gas in the Australian economy is not always Australian Treasury 2011 6.2 9.3 6.2 9.3 (SKM-MMA) obvious – for every gigajoule consumed directly by an end-user, an equivalent amount of gas has been used to help produce some Average 7.3 9.6 9.2 9.9 other type of energy. Notes: Where necessary, data adjusted using CPI to Dec 2012 Sources: AER (2012); BREE (2012c); BREE (2012b); ACIL Tasman (2012); AEMO (2011); ROAM Consulting (2011); SKM MMA (2011)

We have used the average of the above forecasts to estimate the impact of such price rises. While this table shows price increases 10 BREE (2012a)

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Figure 4: Share of gas consumption by use and state in 2010-11 Figure 5: Average household gas bills by state, $2012-13

Residential 2012-13$ per gas customer 10% NT 3% SA Tas. 1200 8% 2009-10 2020 Electricity NSW 1000 Supply WA 11% 33% 42% 800 Industry and Qld Transformations 16% 40% Vic. 600 18% 400

Source: BREE (2012a) 200 1.5.1 Household gas use 0 Households use around 150 petajoules of gas a year, or 10 per NSW Vic. Qld SA WA Tas. cent of Australia’s gas consumption. Victorians use more than 100 petajoules – two thirds of the national household total.11 Notes: Assumes volumes remain at 2009-10 levels in 2020. New South Wales values include data for the Australian Capital Territory. Across the country, people are worried about the rising cost of Sources: ABS (2011b); ABS (2011a); ACIL Tasman (2010); AER (2012); BREE (2012a) household energy bills after rapid increases in electricity and gas prices in recent years. Victorians are particularly exposed to the Across Australia, households are likely to pay an extra impact of rising gas prices. $544 million a year in retail gas bills in the next few years. In Victoria, the cost increases will be most acute. Our analysis, Figure 5 shows how household gas expenditure varies among illustrated in Figure 6, suggests that higher wholesale costs will Australian states. Victoria’s extensive pipeline network makes gas put around $170 extra onto the annual gas bill of the average available to most metropolitan households. Its relatively cold Victorian gas customer. winters also increase household demand for gas for heating.

11 Ibid.

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Figure 6: Potential annual increase in household gas cost, 2009-10 our analysis suggests that rising gas prices could cost industrial to 2020, $2012-13 users up to $3.2 billion a year. It is likely that industrial users 2012-13$ per gas customer would take steps to reduce their gas use in response to higher 180 prices, so the actual impact to industry could be substantially lower. 160

140 Figure 7: Annual energy use by industry sector: all consumption, less residential use and electricity supply, 2010-11 120 Petajoules 100 500 450 80 400 60 350 300 40 250 20 200 0 150 NSW Vic. Qld SA WA Tas. 100 Note: Assumes volumes remain at 2009-10 levels in 2020. 50 Sources: ABS (2011b); ABS (2011a); ACIL Tasman (2010); AER (2012); BREE (2012a) 0 1.4.2 Industrial gas use

In 2010-11, a little over 1500 petajoules of gas were used in the Australian economy. 12 Removing the gas used by households and for electricity supply, around 860 petajoules were used for Source: BREE (2012a) industry or in industrial energy transformations; 57 per cent of all gas used in Australia. Assuming no change in levels of gas use, As Figure 7 shows, this cost will not be distributed evenly across the economy. A large portion of gas consumed in Australia is used by a relatively small number of gas-intensive industries, 12 BREE (2012a) Table F

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mostly in manufacturing. In several industries – including fertiliser, Groups representing affected companies maintain that higher gas petrochemical, aluminium, cement and brick manufacturing – gas prices pose a major threat to Australian manufacturing, already is a material cost. under pressure from high labour costs and a high exchange rate.13 Similarly, the cost will not be distributed evenly by state. As shown in Figure 8, over half of the total cost increases to industrial users, The Australian Industry Group, an industry association, recently a total of almost $1.8 billion, could be borne in Western Australia. surveyed gas users in New South Wales, Victoria, Queensland and South Australia on their experiences of obtaining gas Figure 8: Potential effect of higher wholesale prices on industry by contracts in the current market. Of 62 respondents to the survey, state, all consumption, excluding electricity supply and the average price for existing gas contracts was around $4.80 a households, $2012-13 gigajoule. 2012-13$ million Of the 29 respondents who were seeking to renew or add to 2,000 existing gas contracts, all of those who were offered contracts 1,800 received offers at prices above the current average, as shown in 1,600 Figure 9. Of particular note, customers who wanted longer contracts (more than two years) or contracts commencing after 1,400 2013 were quoted an average price of $8.70 a gigajoule - much 1,200 higher than the average price of $5.10 a gigajoule for short term contracts (less than two years) from 2013. 1,000 800 To some extent, the higher price for gas contracts beyond 2015 reflects the broader state of the gas market. Facing high levels of 600 uncertainty about future prices, suppliers may be reluctant to sign 400 long term contracts. If buyers want to lock in their gas costs, they 200 will have to pay high prices. However, this does not make matters easier for buyers, who may be forced to accept higher gas prices, 0 less certainty around their future fuel costs, or both. NSW Vic. Qld WA SA Tas.

Note: Assumes volumes remain at 2010-11 levels in 2020. Source: ACIL Tasman (2010); AER (2012); BREE (2012a)

13 AIG (2013b)

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Figure 9: Gas prices offered for new contracts, 2013 higher gas prices on brick prices has raised the cost of a new 14 $ per gigajoule house in Perth by $1352. 10 In some cases, companies with options to source cheap gas in 9 other locations may move operations outside Australia. Incitec 8 Pivot notes in its 2012 annual report that “comparing potential projects in Australia and the United States a significant difference 7 lies in the price of our major raw material, gas.”15 6 Average of 5 The government should resist pressure from particular user existing groups urging it to intervene in the market. Australia has far more 4 contracts to gain than to lose from the global gas revolution. Nevertheless, 3 both government and industry should take measures to ensure the market works effectively. Chapter 2 sets out in detail what 2 these measures are. 1 0 1.5 The medium-term price outlook is uncertain Average Price Average Price (2 years or less, from 2013) (all others) Gas prices in the USA have started to rise modestly after an extended period of low prices (see Box 3). Prices at the Henry Source: AIG (2013a) Hub, the price point for gas futures contracts traded on the New York Mercantile Exchange, have recently risen from record lows Higher gas prices will have a negative impact on some industrial of $2 a gigajoule to $4, and there are forecasts that they could users. The fact that significant price increases simply reveal the rise to $6 by 2020.16 If the US Government were to lift restrictions working of efficient markets will not make the pain any easier. on gas exports to countries without free trade agreements with the USA, as recent decisions suggest that it might, the current There is evidence to suggest that companies are already passing domestic price of $4 would translate into prices of $10 to $11 in costs on to customers. Brickworks, a clay and concrete products manufacturer that operates nationally, maintains that the effect of

14 Roberts (2013) 15 Incitec Pivot (2012) 16 PIRA (2013)

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Box 3: Cheap gas in the USA Japan, well below recent contracted prices of more than $15 a Figure 2 shows how gas prices in Japan, Europe and the USA gigajoule. have diverged in recent years. So, why have US gas prices been so low compared with prices in other parts of the world? The impact of US exports would be downward pressure on Asian prices, and therefore prices in Australia. This would also tend to The first explanation is that many US shale gas wells also be the case if Japan restarts a significant number of its nuclear produce liquid hydrocarbons, or ‘liquids’, which are found in power stations or if other countries in the region, such as China, some natural gas wells and extracted when the gas is 17 were to develop a local shale gas industry. There is also potential processed. The liquids can substantially improve the for shale gas development in Australia, 23 although, again, the economics of a gas well, so producers are willing to sell the economics are speculative. The recent decision of KOGAS, a gas at low prices. Many US shale gas fields have high liquids 18 Korean gas firm, to withdraw from negotiations with Chevron to content, whereas coal seam gas fields have almost none. buy gas from the Gorgon project in Western Australia indicates that the company believes lower-priced supplies of gas may soon Further, US gas markets have developed differently to become available.24 Australian markets. Unconventional gas supplies in the US were developed mainly for the domestic gas market, which 19 The outlook for international gas prices is highly uncertain. Even used over 25,000 petajoules of gas in 2012. Barriers to gas so, depending on contractual arrangements, this should not exports have helped to keep supplies high and prices low. It adversely impact the long-term contracts underpinning committed has also been argued that US gas prices have been driven to 20 LNG infrastructure in Queensland. However, there is much less unsustainably low levels as the result of a supply glut. certainty for proposed LNG projects on both sides of the Australian continent where contracts for the sale of LNG have yet These forces have combined to create a market where “gas is to be negotiated, and for domestic gas prices in the medium-term, so cheap that it’s no longer profitable to drill”.21 Further, the that is, beyond the next three to five years. US Government has begun to lift export barriers.22 It seems inevitable that US gas prices must rise in future to more sustainable levels.

17 EIA (2013a) 18 John Williams Scientific Services (2012) 19 EIA (2012) 20 Dicolo (2013) 21 Philips (2012) 23 Australian Council of Learned Academies (2013) 22 Spectator (2013) 24 Klinger (2013)

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2. How should government and industry respond?

2.1 Governments should not revert to protectionism government - from whether any kind of tax on producers should be used to subsidise domestic manufacturing. The prospect of rising gas prices has prompted some manufacturers to urge Australian governments to impose price Three specific reasons why trade protections are not warranted controls on gas, to restrict LNG exports, or to force LNG for the Australian gas industry are outlined below. producers in eastern Australia to commit a portion of their gas to domestic users, as already happens in Western Australia. There is no market failure

Imposing a requirement that producers must reserve a fixed Many arguments for domestic gas reservation or quotas assume volume or proportion of gas for domestic manufacturing that markets have ‘failed’ in some way and that governments consumers is a form of industry protection. The economic benefit should therefore intervene. of the gas resources is shifted from producers to particular industry consumers. This redistribution “would be achieved at a While some industry claims about the economic effects of higher net cost to the Australian community”, according to the Bureau of gas prices appear to be exaggerated (see Box 4), the emerging Resources and Energy Economics.25 More bluntly, economics gas market and expected rising prices will prove challenging for professor Stephen King has described such a reservation scheme some gas users. High demand for gas has shifted the balance of as “blatant, inefficient and inequitable”.26 market power towards the gas producers and away from the wholesalers and large industrial gas users who buy gas from Chapter 4 contains a more comprehensive assessment of them. If buyers are unwilling to pay higher prices to sign long-term reservation policies as applied in Western Australia. contracts, they may have to sign shorter contracts and accept the risk that prices will move in coming years. Recent public commentary has asserted that Australian governments have failed to extract the best value from the Yet, these conditions reflect the dynamics of the underlying resources boom. 27 Yet it is important to separate the question of market; not a market failure. Our analysis found limited evidence whether taxes on gas producers should rise - a valid question for that gas will not be available to users who are willing to accept higher prices and be flexible with contract terms. In the absence of a genuine market failure, it is in the interests of the Australian

25 BREE (2012c) economy to allow gas to flow to the users that value it most highly. 26 King (2013) 27 eg Warwick McKibbin in Kehoe (2013)

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Box 4: 'Multipliers' and dodgy economics It also assumes that production inputs would not be put to other Higher gas prices will disadvantage a small number of uses, which is clearly not the case – gas is clearly in demand Australian industries that use large amounts of gas as a from other sections of the economy and this is why prices are production input or fuel source. High prices could lead some increasing. Further, multipliers assume that policy makers have manufacturing facilities to close, causing some job losses. no ability to influence employment and economic activity However, some in the manufacturing sector have greatly through fiscal and monetary policy settings. exaggerated the size and impact of these losses. None of these assumed conditions would hold, except under Dow Chemical is a large industrial gas user. In an opinion piece extreme conditions that are not relevant to the current Australian for The Australian newspaper, Dow’s CEO called for policy context. intervention in the gas market to ensure natural gas prices that Multipliers also suffer from ‘double counting’ as each industry are “affordable and stable”. He wrote: implicitly takes credit for growth in other sectors of the economy. “Transformed through the manufacturing process, As Richard Denniss of The Australia Institute noted: natural gas actually creates eight times more value for “…if there were 10 million people in the Australian the economy than when it is burned or exported.”28 workforce and each industry sought to estimate their The “eight times” multiple ascribed to the manufacturing sector direct and indirect contribution to employment then collectively their claims would add up to 18.7 million is called a ‘multiplier’. Multipliers are calculated by assuming 29 that all industries in the economy are related to all other workers.” industries. It is assumed that an increase in production in one The Australian Bureau of Statistics stopped publishing data on sector will have calculable ‘flow on’ effects to other sectors. economic multipliers in 2001-02 because: Unfortunately, the argument is deeply flawed. “There was considerable debate ... as to their suitability This type of analysis makes the extreme assumption that no for the purposes to which they were most commonly worker would find another job if a manufacturing facility closed. applied, that is, … to support bids for industry assistance of various forms.”30

28 Liveris (2013) 29 Denniss (2012) 30 ABS (2010)

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Potential effects on LNG investment technological change, global integration and fiercer competition from abroad.”32 Large investments in LNG have been committed on the basis of existing government policies. Any changes to these policies Overwhelmingly, Australian and international experiences of trying should be considered in light of the potential impact they may to protect domestic industries by restricting trade have damaged have on Australia’s attractiveness as an investment destination. the broader economy. Changes applied retrospectively to committed LNG projects would damage Australia’s chances of securing future investment. Trade barriers reduce productivity and blunt companies’ incentives to innovate. Protecting some industries from Western Australia gas reservation quotas were negotiated before international prices prevents economies from shifting investment LNG proponents committed to investments. Proponents who have and labour to firms or industries that are more competitive. argued for an east coast gas reservation frequently fail to Protectionism also encourages firms to direct resources into acknowledge that policy implemented at this late stage of project lobbying governments, at the expense of more productive development could significantly damage investors’ confidence in investments. the stability of Australian regulatory arrangements, and could deter investment.31 A reservation policy applying only to future Evidence supports the view that trade protections make domestic projects would be less damaging, but would be unlikely to relieve industries less efficient: pressure on markets during the crucial transition period. • A recent World Bank study suggested that liberalising trade Protectionism will not work protections boosted per capita GDP growth by between 1.2 and 2.6 per cent.33 Reflecting in 2009 on Australia’s experience with trade protection in the mid-1980s, the Productivity Commission noted that: • A European Bank of Reconstruction and Development study showed that, as a result of a domestic quota on wheat sales in “large parts of the economy were inefficient, inward 2010-11, foreign investors held back €550 million of capital to looking and inflexible. … Australia was not well placed to avoid the risk of further intervention.34 respond to the changes and challenges arising from rapid

32 Productivity Commission (2009) 33 Salinas and Aksoy (2006). The sample controlled for countries that were subject to major exogenous disruptions and its results were statistically significant under all specifications. 31 For examples, see DomGas Alliance (2012); NIEIR (2012) 34 Götz, et al. (2013)

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Evidence suggests that while there may be benefit in protecting LNG exports could affect the public interest.38 This study some infant industries,35 such industries rarely receive assistance. examined 13 separate scenarios, varying the outlook for the US Rather, large, established industries that can exert pressure on gas supply and making a range of assumptions about gas export government are the ones that are helped.36 restrictions. In every scenario, NERA forecast that the USA would receive an economic gain from allowing LNG exports. Further, Further, there is no clear evidence that the gas reservation policy scenarios with unlimited exports always had higher net economic applied in Western Australia has delivered low gas prices for gas benefits than corresponding cases with limited exports.39 users. Western Australian gas prices are currently higher than those on the east coast. It is expected that in 2020, after the east This suggests that there is little to be practically gained from coast gas market has been exposed to several years of gas imposing ‘public interest’ or ‘national interest’ tests for LNG export exports, east coast gas prices will remain lower than west coast projects. Rather, such tests have the potential to impose a prices (see Table 2). regulatory burden on developers and provide a platform for future lobbying by user groups. Explicit reservation policies are not the only form of industry protection that has or could be proposed by lobby groups Nevertheless, there are important actions governments should concerned about rising process. For example, some industry take to ensure the market works well. groups and companies have argued for a ‘national interest’ or ‘public interest’ test.37 This would impose an additional hurdle 2.2 Resolving the coal seam gas impasse in New South requirement on future LNG projects seeking regulatory approvals. Wales However, evidence suggests that such policies do not achieve 40 41 favourable economic outcomes. Companies and government agencies are both concerned that New South Wales could face a gas supply shortage between In late 2012, the US Department of Energy commissioned NERA 2015 and 2017. There is no shortage of gas in the ground, but Economic Consulting to conduct an independent study of how US there are concerns about thet ability to get it to the New South Wales market on a peak day for gas demand.

35 Although New South Wales reserves are only a tenth of those in In theory, protecting an infant industry can improve net welfare if it meets two Queensland, gaining access to them could be critical if gas from criteria: a) it will eventually survive international competition without protection, and b) the discounted future benefits it will produce outweigh the present cost of protection. These are known as the Mill and Bastable tests, respectively. 38 NERA Economic Consulting (2012) Harrison and Rodriguez-Clare (2010) 39 Ibid. 36 Ibid. 40 Baulderstone (2013); SMH (2013) 37 See: Dow (2012); Manufacturing Australia (2013) 41 Department of Energy and Water Supply (2012); AER (2012)

Grattan Institute 2013 18 Getting gas right: Australia’s energy challenge

the Cooper Basin is diverted to Gladstone and the pipelines from With such options available, producers have suggested that Victoria are insufficient to consistently meet New South Wales concerns about a shortfall are commercial posturing. They say demand. Yet the concerns of farmers, landowners and they are as willing as ever to write gas contracts,45 but that environmentalists have led the government to restrict customers are not prepared to make long-term commitments to development of coal seam gas, which makes up all of the gas underpin supply contracts. The truth is not clear but the tension is reserves in New South Wales. high. Unsurprisingly, the protagonists take positions that align with their commercial interests. For example, potential developers of Amid the claims and counter-claims that have accompanied these coal seam gas projects in New South Wales have an incentive to developments, industrial customers seeking secure supplies for put maximum pressure on governments to support coal seam gas five years or more are reporting that they cannot get contracts on development in the state. the east coast “at any price”.42 In a recent Australian Industry Group survey of 31 industrial gas users seeking to renew or add The Australian coal seam gas sector has been slow to respond to to gas contracts, 10 per cent of respondents reported that they community concerns. In New South Wales the result is a could not obtain a quote and 32 per cent indicated they could not stalemate. The economic benefits of development are significant, obtain a quote at a price considered acceptable.43 Companies yet the risks of inappropriate or poorly regulated development are such as Dow Chemicals and industry associations such as the of great concern to many members of the community. The current Plastics & Chemicals Industry Association have called for a range position is almost certainly unsatisfactory for all players. of measures to ensure supply. 44 These include extended reservation of gas for domestic users, a moratorium on LNG A better response can be found in the recent creation of a Center exports, rebates for ‘transformational industries’, and greater for Sustainable Shale Development in the USA. Significant shale market transparency. gas developers, including Shell and Chevron, have joined with environmental groups to create a set of standards for the use of But Australia has enough gas to solve this problem. New South hydraulic fracturing in the north-eastern United States. These Wales gas demand could be met by ramping up coal seam gas standards will form the basis of the Center’s independent, third- production to reduce drawing on conventional gas supplies, by party certification process. Australian industry could learn from increasing production from the Cooper Basin or by increasing the this initiative. capacity of gas pipelines from Victoria to New South Wales.

45 A representative of Origin Energy advised that “Origin Energy is currently 42 DomGas Alliance (2013) and others quoting gas supply contracts for domestic customers. The duration of these 43 AIG (2013a) contracts can vary from less than two years to up to 10 years.” Pers Comm. 44 PACIA (2013) Origin Energy (2013).

Grattan Institute 2013 19 Getting gas right: Australia’s energy challenge

Through the Standing Council on Energy and Resources – which 2.3.1 Joint marketing arrangements should be tightly includes all relevant ministers – Australian governments must constrained come together with industry and environmentalists to develop clear and predictable guidelines for coal seam gas development. Many gas fields are owned by several companies, who form a The Standing Council’s recent endorsement of a national, consortium to develop a gas field. This structure can be effective. harmonised regulatory framework for coal seam gas is a Project partners may invest together because they have beginning.46 Further steps are needed to resolve the impasse and complementary skills, because a project is too large for one the right balance must be found quickly. company to undertake independently, or as a way of improve risk- sharing along the supply chain. An example of the last would be 2.3 Creating efficient market frameworks when an end user of gas, who is not a development specialist, takes an equity stake in a project to hedge their gas costs. The risk of supply constraints in Australia’s east coast markets is real. However, these potential constraints are likely to be resolved Joint venture arrangements, by themselves, do not pose a before they materialise. The solution will be for commercial problem for gas market efficiency. Joint ventures are able to sell players to deliver more supply. Wholesale participants such as gas as a single entity, but are subject to constraints under the gas retailers AGL and Energy Australia will have to obtain supply, Trade Practices Act. However, in some cases the Australian while industrial customers will either negotiate at higher prices or Competition and Consumer Commission (ACCC) has permitted seek alternative fuels. The negotiations may prove difficult, and gas field consortia to jointly market and sell the output of gas may come with heavy price tags in the short term. But these fields even where there is no joint venture arrangement in place – problems are for industry, not government, to resolve. an arrangement known as joint marketing. Joint marketing is usually justified on the ground that reduced risks and shared By contrast, market failures or barriers to the efficient supply-side marketing costs lead to lower costs that are then passed on to response are appropriate areas for government action. The customers. following actions will not directly reduce prices or guarantee supply. But they will improve transparency and liquidity and lead Yet joint marketing reduces competition within the upstream gas to a more mature and robust gas market. sector by reducing the number of sellers in the market. Gas customers have argued that because there are usually only a small number of gas fields supplying any market, removing joint marketing would improve competition.

As the east coast market has matured, becoming an

46 interconnected market with multiple suppliers from several SCER (2013)

Grattan Institute 2013 20 Getting gas right: Australia’s energy challenge

primary fields, both the arguments for and concerns about joint Increasing price transparency in the gas market would have marketing have fallen away. In Western Australia, however, the several benefits. It would help businesses manage the transition evolution has been slower. The ACCC has authorised joint to higher gas costs by providing more reliable gas price estimates marketing by gas developments including the Gorgon Project. In for business planning processes. It could also facilitate trading its 2009 decision, however, the Commission only gave between industrial gas customers and gas retailers as it would authorisation until 2015, recognising that the market may be give customers a way to benchmark prices. beginning to exhibit greater diversity and potential for competitiveness. As markets continue to grow in depth and An industry-led proposal to develop a gas price index was initiated breadth, the ACCC should be increasingly sceptical of the in 2012 and referenced in the Commonwealth Government’s 47 justification for ongoing joint marketing arrangements, with a view Energy White Paper but is currently on hold. The delay has to ultimately removing the practice. been attributed to global concerns regarding the development and use of price indices. In a recent United Kingdom case, bankers 2.3.2 Governments should encourage greater price were found to have manipulated the London Inter-bank Offer Rate transparency (LIBOR), an interest rate index. This has sparked broader concerns about the vulnerability of price indices to manipulation. The setting of gas prices has historically been dominated by long- An international review of the LIBOR case will be released in the term contracts between gas producers and the wholesale market. second half of 2013. As the gas market has developed both financially and physically, major consumers and producers have recognised the limitations If the regulatory challenges can be resolved, and they should be, of this structure in providing the best result. For example, during a development of a price index would enhance price transparency period of rapid change, the lack of transparent prices makes it and increase competition. Governments should play a role in difficult for users to assess whether gas prices will rise and, if so, providing regulatory guidance, bringing together market by how much. participants or promoting participation in developing a price index mechanism. In recent years, there has been progress towards short-term markets. This includes short-term trading markets operated by the 2.3.3 Governments should act to eliminate barriers to Australian Energy Market Operator, the Victorian gas wholesale pipeline access market, the national gas market bulletin board and the proposed gas trading hub market in Queensland. The first three are in place The ability to transport gas between major markets is limited to and the fourth is planned for introduction in 2014. Although it the capacity of pipelines that connect the markets. Investment in could be many years before the Australian gas market is not underpinned by long term contracts, these are all good moves. 47 DRET (2012)

Grattan Institute 2013 21 Getting gas right: Australia’s energy challenge

new pipelines is expensive and may not be economically justified sellers, it is hoped that capacity markets would increase but it may be possible to use existing infrastructure more competition and lower gas prices. effectively. Improving access to pipeline capacity would assist to improve competition in east coast markets. The Australian Energy Market Operator is considering the development of two capacity trading products: a monthly forward The lack of transparency in gas markets makes the prospect of a product and a bulletin board style capacity exchange. These capacity market attractive. In the current market, there is a products are aimed at overcoming barriers between capacity substantial risk that a party wanting to obtain pipeline capacity owners and potential buyers at the Wallumbilla gas hub. The and a party willing to sell would not find each other. This may Wallumbilla trading hub is planned for introduction in early 2014, occur because potential buyers do not know who owns the coinciding with the beginning of LNG exports. existing capacity or because the effort of contacting capacity holders to find a counterparty would be greater than the potential While current proposals for a capacity trading market have 48 reward. A market could help facilitate efficient transactions. centred on Wallumbilla, the concept could be applied to other pipelines and could be regarded as a way to improve competition Further, in the absence of a capacity market, buyers seeking in other regions. In May 2013, the Standing Council on Energy pipeline capacity or sellers with spare capacity would generally and Resources released a consultation paper on the trade in buy or sell to the owner of the pipeline. This occurs because natural gas transmission pipeline capacity.49 This process will buyers and sellers have limited information on which other market examine ways that unused pipeline capacity may be traded. participants want to trade. Because of the high cost for buyers and sellers to find each other, the pipeline owner has little Accelerating development of this reform is warranted to take incentive to offer competitive prices to buy or sell capacity. By account of the pressing need for market flexibility over the years offering an alternative mechanism to buy or sell, a market could immediately following the commencement of LNG exports. lower the price of pipeline capacity. Regulatory agencies, governments and industry groups have By allowing for short-term capacity trading, it is also hoped that contemplated some of these reforms. But they are not happening new sellers will enter into regional gas markets. For example, a fast enough. In the next four years, east coast gas demand is set gas producer may have some spare gas processing capacity for a to increase fourfold. The markets must mature as they grow. short period. The difficulty of getting the gas to market may mean that capacity is not used. If the producer had ready access to reasonably priced pipeline capacity, it may elect to transport gas to a regional gas market to sell. By increasing the number of 48 AEMO (2013) 49 SCER (2013)

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2.4 Share the benefits governments to address. Second, supply infrastructure may be physically unable to meet growing demand in the short term, Australian gas, as a natural resource, is owned by the Australian leading to a squeeze on supply and higher prices. To ensure this people. It is therefore appropriate that as LNG exports begin to latter issue does not arise, industry must quickly and visibly expand rapidly, Australian governments should ensure that respond to potential infrastructure limitations. Australians are being appropriately compensated for the sale of these assets. If supply constraints push up prices for residential and small business consumers, governments will be pressured to act in For the purpose of this report, tax and royalty arrangements for counter-productive ways – by re-introducing retail price controls, the natural gas industry were not reviewed. However, the for example. Therefore, it is in the self-interest of industry to argument that Australians have more to gain from trading LNG demonstrate to government that it can solve the supply problem. than they have to lose from higher prices assumes that There have been signs of such a response in announcements by appropriate tax and transfer systems are in place. Governments Santos and Origin that specific tranches of contracted gas will be should ensure that this is the case. allocated to meet domestic demand.50

Protectionist policies impose an implicit tax on gas producers by 2.5.2 Gas users: adapting to higher prices forcing them to sell gas at prices lower than those they could achieve in an unconstrained market. An explicit tax regime is a Affected industries can mitigate the impact of higher gas prices in more efficient means of collecting revenue. It also allows more a number of ways. They can switch to other fuel sources, pass flexibility for governments to decide how to spend that revenue, costs on to customers or shift operations to other locations - in whereas protectionist policies confer all of the benefits on gas some cases, possibly outside Australia. users. The managing director of Brickworks has noted that higher gas 2.5 Challenges for industry prices have prompted the company to use sawdust to fire a kiln in Tasmania and “methane from landfill operations at several sites 2.5.1 Gas Producers: ensuring supply on the mainland”.51 Such adaptations can mitigate the impacts of higher gas costs. There are two reasons that a potential supply issue could arise in the gas market, even though there is no shortage of gas in the ground. First, there could be a problem if the market experienced a ‘market failure’ or if barriers impeded the efficient response of 50 the supply side to increased demand. This is an issue for Chambers (2013b); Chambers (2013a) 51 Roberts (2013)

Grattan Institute 2013 23 Getting gas right: Australia’s energy challenge

Figure 10: Total use value for industries sensitive to high gas suggesting that producers will be able to raise prices to help prices: Australian production vs imports, 2008-09 absorb the impact of higher gas costs. $ million The following two chapters examine the gas industries on the east 35,000 Imported and west coasts, and how governments and industry should Domestic respond to the different challenges they present. 30,000

25,000

20,000

15,000

10,000

5,000

- Basic Chemical Glass and Glass Ceramic Product Manufacturing Product Manufacturing Manufacturing Source: ABS (2010)

In some cases, it is not firms but the end users of a product that will ultimately bear the cost of higher gas prices. This will occur when most of the product consumed in Australia is produced domestically. In this case, producers are able to raise prices to cover higher input costs without losing sales to imported products. Figure 10 shows the total trade exposure for three industries where gas comprises over 5 per cent of total input costs. In each case, most domestic demand is supplied by domestic production,

Grattan Institute 2013 24 Getting gas right: Australia’s energy challenge

3. Gas on the east coast Figure 11: Major pipelines and gas fields in eastern Australia 3.1 A shifting market

For decades, eastern Australian gas markets have been relatively stable. Deals to buy and sell gas have mostly been negotiated through contracts lasting up to 20 years. These contracts have underwritten the development of large gas reserves. Major industries have benefitted from being able to secure gas supplies to align with their long-term investments.

However, the beginning of east coast gas exports from 2014 is set to create higher and more volatile prices. New sources of gas are coming online and existing long-term contracts are expiring. Both government and the gas industry have roles to play in guiding the market through this period of transition.

3.2 Coal seam gas

As in the USA, Australia’s east coast gas reserves have greatly increased due to the new capacity to extract unconventional gas (see Box 2 for a description of unconventional gas). While the main type of unconventional gas in the USA is shale gas, unconventional gas production on Australia’s east coast is currently dominated by coal seam gas.

‘Proven and probable’ gas reserves more than tripled between 2005 and 2012 due to the discovery of more coal seam gas reserves, as Figure 12 shows.52 Coal seam gas has grown from a

52 Source: Grattan Institute AER (2006); AER (2007); AER (2008); AER (2009); AER (2010); AER (2011); AER (2012)

Grattan Institute 2013 25 Getting gas right: Australia’s energy challenge

small share of total gas reserves a decade ago to 85 per cent of The development of the coal seam gas industry has provoked east coast reserves in 2012. Based on current reserves and concerns that water extracted from coal seams could pollute local consumption levels, current eastern Australian gas reserves will water supplies, or that fracking (see Box 2) could pollute last for nearly 70 years (see Table 1).53 groundwater. Land-owners have objected to coal seam gas producers developing gas wells and access roads on privately Figure 12: ‘Proven and probable’ gas reserves in eastern Australia, owned land. In February 2013, these objections led the New 2006 to 2031 South Wales Government to impose tighter restrictions on the industry and instigating a review into the state’s coal seam gas activity.54

Restrictions on coal seam gas development in New South Wales are unlikely to materially affect the supply of gas for export projects. Of Australia’s extensive coal seam gas reserves, around 93 per cent are held in Queensland. They underpin the development of LNG export projects. All the same, about 2900 petajoules of coal seam gas is available in New South Wales. If developed, this would make a material difference to New South Wales supply security and would be one way of alleviating potential supply constraints from other sources as described later in this chapter.

3.3 The export market

The east coast of Australia has vast reserves of gas, existing pipeline infrastructure and a relatively small level of domestic gas demand. These features make gas exports attractive. Source: AER (2006); AER (2007); AER (2008); AER (2009); AER (2010); AER (2011); AER (2012); AEMO (2012a) Gas exports are forecast to occur for the first time on the east coast from late-2014 and are expected to have a dramatic effect on the market. Between 2013 and 2017, east coast gas demand

53 54 AER (2012); AEMO (2012a) The Hon Barry O'Farrell (2013)

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is forecast to increase fourfold: from about 700 to 2800 petajoules Four main groups are developing LNG terminals: a year. • Queensland Curtis LNG is owned by QGC, a wholly owned Figure 13 provides the Australian Energy Market Operator’s most subsidiary of the UK oil and gas company, BG Group.55 recent forecast for east coast gas demand over the next two QCLNG has committed to developing two LNG trains, which decades. The scale of LNG development is immense. The five will start exporting gas in 2014. LNG trains that are under construction in Queensland are forecast to require $50 billion of capital expenditure. A further three trains • Australia Pacific LNG is a joint venture between Australia’s are forecast to be developed before 2018. Origin Energy (37.5 per cent), ConocoPhillips from the USA (37.5 per cent) and China’s Sinopec (25 per cent).56 APLNG is Figure 13: Forecast gas demand for eastern Australia developing one LNG train, which will commence exports in Petajoules per year 2015, and is expected to develop a second train by 2016. 3,500 • Gladstone LNG is a joint venture between Australian gas 3,000 producer, Santos (30 per cent), Malaysia’s Petronas (27.5 per cent), French firm Total (27.5 per cent) and Korean KOGAS 57 2,500 (15 per cent). GLNG is developing two LNG trains, which will Export start exporting gas in 2015. 2,000 • Arrow LNG is a joint venture between Dutch firm Shell and Chinese firm PetroChina.58 The two firms own equal shares in 1,500 the project. Arrow LNG has proposed to develop two LNG trains but has not committed to the projects. It has been 1,000 Domestic suggested that if domestic gas prices rise, Arrow LNG may 500

0 2008 2012 2016 2020 2024 2028 2032 55 QGC (2013) 56 Source: AEMO (2012a) APLNG (2013) 57 Santos (2013) 58 Arrow Energy (2013)

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forego developing LNG trains to sell gas to other LNG projects Figure 14: Gas flow in eastern Australia on 8 June 2011 (terajoules) or gas users.59 Demand centre Bowen- 3.4 Pressure points 585 Qld Surat Supply source 516 basins Projects being developed on the east coast are the world’s first Pipeline LNG projects to depend on coal seam gas as the source of 69 supply. While conventional gas may be extracted from a single well, coal seam gas is produced from thousands of much smaller Cooper NSW basin 610 wells over wide areas. Each well may have its own production 330 15 challenges. This makes it harder for producers to predict output Camden from a coal seam gas field, relative to a conventional field. 157 7 CSG 257

The consequences of delays in production to supply LNG exports SA Vic Gippsland could be severe. If coal seam gas wells do not deliver as much 366 1160 771 basin 209 375 gas as planned, LNG projects may seek to source extra gas from 22 53 the domestic market. This could put further pressure on domestic Otway- Vic Tas gas prices, on top of the price pressure from linking to global Bass Storage markets and higher production costs. basins 53

Figure 14 illustrates gas flows in eastern Australia on 8 June 2011 Source: National Gas Market Bulletin Board (2013) and Grattan Analysis – that year’s peak day for aggregate gas demand. This analysis illustrates the challenge for the east coast market in coming years. New South Wales relies more than other markets do on gas imports from other states, as Figure 15 shows. It has lower levels of gas production capacity than any state except Tasmania. Instead, it imports gas from other states via pipelines. The approach has worked so far, yet the lack of local production leaves New South Wales more exposed than other states in the event of an east coast supply constraint.

59 Macdonald-Smith (2013)

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Figure 15: Daily capacity of gas infrastructure by state, 2012 exporters are now sending it north to supply Queensland LNG facilities. Terajoules per day 2,500 Figure 16: Possible gas flow on a peak gas day in 2016 (terajoules)

2,000 Bowen- 605 Qld Exports Surat 832 4,838 1,500 Basins 227 NSW 1,000 Cooper Demand:633 NSW Basin SA 128 20 Supply: 480 500 Camden 44 35 CSG 288 Tas Qld Vic 0 SA Vic Gippsland Pipeline Capacity Local Production 349 1171 778 Basin (Interstate Imports) 314 353 84 79 Otway- Vic Source: Core Energy Group (2012) Tas Bass Storage 79 3.4.1 Potential constraints in New South Wales Basins

Note: Supply to New South Wales is constrained by processing capacity at Cooper, which To illustrate how gas markets on Australia’s east coast could is assumed to be 390 terajoules a day. Supply from the Victorian storage facility may be lower if operators can anticipate demand and increase the flow of gas become constrained, Figure 16 shows possible gas flows on a from the Otway Basin. Export demand is based on the average daily requirement peak gas day in 2016. to supply 1,766 petajoules of export demand for 2016, as per AEMO’s planning case forecast. It is assumed that export demand is supplied from additional gas fields (not shown). We have assumed that no new coal seam gas fields or new Source: National Gas Market Bulletin Board (2013) and Grattan Analysis processing capacity have been developed, and that the flow direction for the pipeline linking the Cooper Basin to Queensland On this hypothetical day, New South Wales experiences a supply has reversed: rather than sending gas to southern markets, gas shortfall of around 150 terajoules, over one sixth of its forecast

Grattan Institute 2013 29 Getting gas right: Australia’s energy challenge

daily demand. This is the result of constraints on gas processing Getting gas from the Cooper Basin capacity at the Cooper Basin now that over half of the gas being produced there is flowing into Queensland. Figure 16 also shows how the Cooper Basin reached the limit on the amount of gas it can produce on our hypothetical peak day. At 3.4.2 Getting gas to New South Wales present, processing capacity is around 390 terajoules of gas a day. Figure 14 shows that this capacity, supplemented with gas The analysis presented in Figure 16 does not imply that gas flowing from Queensland, was enough to supply South Australia supplies will necessarily fall short in New South Wales – only that and New South Wales on the busiest day in 2011. Yet by 2016 a shortfall is a real possibility if action is not taken. There are a Queensland is forecast to require imports from the Cooper Basin, number of solutions that could be implemented before the issue rather than being predominantly a source of supply. becomes severe. Supply constraints are only likely to emerge on days when demand for gas is high, so solutions that do not Companies are already working to address this issue. In May, involve major expansions or expenditure are particularly Santos, a gas producer with a large stake in the Gladstone LNG attractive. export project, announced that it would expand production capacity at the Cooper Basin to 550 terajoules per day by 2015,60 Coal seam gas developments an increase of 140 terajoules. This is a substantial increase in capacity and will assist in managing demand in New South Wales. As Section 2.2 sets out, governments, industry and community groups need to resolve the impasse on coal seam gas Increasing production in Queensland development in New South Wales. If coal seam gas can be developed, it could produce more than enough gas to meet the The analysis in Figure 16 assumes that capacity on the pipeline additional gas demand in New South Wales on a peak day. flowing from the Cooper Basin to Queensland is fully utilised. This includes the 85 terajoules of capacity now available, plus an extra If it is determined that coal seam gas development poses 142 terajoules forecast to be available from 2015. unacceptable risks or cannot win community acceptance, then alternatives are available. However, companies may be unwilling Alternatively, if more gas can be supplied from coal seam gas to invest in other solutions if they believe that approval of coal fields in Queensland it may be possible to reduce the amount of seam gas developments is imminent. The Commonwealth and gas flowing from the Cooper Basin. This can only occur if New South Wales governments need to provide clarity and producers in Queensland have enough resources to develop certainty to industry. more gas fields, recognising the extensive developments already

60 Santos (2013)

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underway in Queensland to supply gas for exports. It would also Gas storage require higher gas prices in New South Wales as a commercial incentive for gas producers to divert the gas, and to underpin In Victoria, a gas storage facility in Dandenong stores gas as higher development costs in Queensland. LNG. It can be filled on days when gas demand is low and used to augment gas supplies on days when demand is high. Gas retailer Increasing pipeline capacity from Victoria AGL is developing a similar facility in Newcastle. Due to open in 2015, it will be able to supply up to 120 terajoules a day to the More gas could be supplied to New South Wales by increasing New South Wales market. the capacity of pipelines flowing from Victoria. The Eastern Gas Pipeline is almost 800 kilometres long and can carry Reducing demand 288 terajoules a day.61 Expanding this pipeline would increase this capacity. Yet it is unclear whether an expansion could deliver In the absence of new supply, the New South Wales gas market gas to New South Wales in time to assist with potential supply will revert to the default mechanism for balancing supply and constraints, or if remaining gas reserves in the Gippsland Basin demand: higher prices. If gas shortages emerge, prices will rise would justify investment in gas transmission infrastructure. and demand can be expected to fall. That will cause gas-fired generators to run less often, particularly if other power generators An alternative is to expand the capacity of the New South are available to meet the state’s electricity requirements. If prices Wales-Victorian Interconnector, a pipeline that connects the rise further, commercial gas users may reduce gas use, switch to Victorian Gas Transmission Network to the New South Wales gas alternative fuels, or even close down operations. network. The interconnector can currently supply up to 44 terajoules of gas a day to New South Wales on a peak day. APA Group, the gas transportation business that owns the pipeline, has proposed to expand this capacity. While an expansion of the interconnector would not independently resolve a large supply shortfall in New South Wales, it may assist in managing demand at the margin. The expansion project is expected to be completed in 2014.62

61 Core Energy Group (2012) 62 AEMO (2012c)

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4. The West Australian gas market Figure 17: Major pipelines and gas fields in Western Australia

4.1 A very different market

Western Australia has huge reserves: around 90,000 petajoules, or 64 per cent of the ‘proven and probable’ gas reserves in Australia.63 Most of them are conventional gas fields, located in deep water off the coast of northern Western Australia. The fields are very large, but more expensive to reach than conventional onshore or shallow-water gas fields. Developing them requires significant scale: in many cases they are viable with contracts in the export market but not to meet domestic demand alone.

Western Australia started exporting gas in 1989 from the North West Shelf project in the Carnarvon Basin.64 This project alone produces about six per cent of all global LNG exports.65 The Western Australian gas market is physically separate to the east coast market. It confronts different challenges. It has fewer buyers and sellers, large distances between major gas fields and demand centres, and fewer major transmission pipelines.

The recent surge in global demand for gas has led to massive new investment in LNG projects in Western Australia. Projects worth at least $116 billion are underway and more are in the advanced planning stage. Western Australia’s gas exports will increase by close to 70 per cent by 2017, as Figure 18 shows.

63AER (2012), p87 64 The NWS is a joint-venture of six participants: Woodside Energy, BHP Billiton Petroleum, BP Developments Australia, Chevron Australia, Japan Australia LNG (MIMI), and Shell Development (Australia) 65 BREE (2012c) Source: Grattan Institute

Grattan Institute 2013 32 Getting gas right: Australia’s energy challenge

Figure 18: Forecast gas demand for Western Australia, 2010 to 2031 gas from the North West Shelf project.67 The deal made the project possible and enabled a major expansion in Western Petajoules per year 3,500 Australia’s gas market. But the contracted volumes were very generous, exceeding local demand.68 This helped to keep prices 3,000 low, compared with export prices, as shown in Figure 19. Export Since the mid-2000s the domestic market has been under strain. 2,500 Western Australia’s minerals boom has driven growth in demand, gas production costs have increased due to higher input costs 2,000 and some fields have been depleted. Moreover, in the coming years the North West Shelf project will complete its original 1,500 obligation to supply gas to the domestic market. Without new domestic contracts it could supply no gas to the domestic market 1,000 after about 2020.69 Prices have risen sharply, from an average $2 to $3 a gigajoule to new contracts at around $8 to $9 a 500 Domestic gigajoule. Some short-term deals have been reported as high as $15 a gigajoule.70 0 2010 2014 2018 2022 2026 2030

67 Soures: ACIL Tasman (2011); Government of Western Australia (2012a) Under the 1979 deal the State Electricity Corporation of Western Australia (SECWA) contracted with the NWS partners to purchase 3,023 petajoules of gas, with a further 2,041 petajoules reserved for domestic use, subject to 4.2 Recent concerns about price and supply commercial viability of production. In addition, SECWA built gas-fired power stations, developed the Dampier to Bunbury Natural Gas Pipeline to connect the When the North West Shelf project began exporting gas in 1989, NWS project to major demand centres in the south, and agreed to market the domestic gas prices did not increase immediately. In part, this gas to Alcoa and other users. SKM (2011) 68 Ibid. reflected much lower prices in major export markets. Japanese 69 prices were around $5 a gigajoule, compared with around $16 a Calculation by SKM (2011). The NWS Joint Venture has indicated that it 66 expects to continue supplying some domestic gas, but less than it has gigajoule today. But prices were also shaped by a major deal in historically. In a State Parliament inquiry into domestic gas prices, the which the State Government committed to buy a large volume of Parliamentary Committee accepted a supply scenario where the NWS continues to supply 600 terajoules per day until 2020, declining to 300 terajoules per day in 2030. Economics and Industry Standing Committee (2011) 66 OECD (2013) 70 SKM (2011)

Grattan Institute 2013 33 Getting gas right: Australia’s energy challenge

Figure 19: Blended average* Western Australia wellhead gas prices To help address this, the Western Australian State Government and Japan LNG import price from Western Australia, 1980 to 2012 has intervened in the market. In 2003, the Government imposed a A$ per gigajoule requirement on the large Gorgon project to supply 2,000 Japan LNG from WA 18 petajoules of gas to the domestic market over the life of the landed import project. In 2006, the Government formalised a policy to reserve 16 gas for domestic use. Under the policy, the Government negotiates for 15 per cent of output from LNG projects to be 14 reserved for sale in the domestic gas market.71 12 4.3 Reserving gas is not the answer 10 The key problem with the domestic gas reservation policy is that 8 government overrides the market and sets the volume of supply. 6 WA blended This has risks. In particular, government could force too much gas average wellhead into the domestic market. Suppliers will have less flexibility to 4 adjust how much gas they supply, and will be forced to compete with one another to sell this gas into the market. This will push 2 prices down and could restart the cycle of poor outcomes that 0 followed the deal with the North West Shelf project. 1980 1985 1990 1995 2000 2005 2010 As the following section describes, years of low prices Notes: * Blended average combines operating gas contracts, some of which were set when discouraged producers from developing new gas fields, leading to prices were substantially lower. Japan prices shown are for landed gas and include transport and liquefaction costs. Historical data for these costs is not little competition and supply constraints. readily available. Currently they run at about $5 per gigajoule, but they would have been substantially lower in the past. Source: OECD (2013); Government of Western Australia (2012b); RBA (2013)

The domestic market needs to bring on new sources of supply. 71 Developers are not explicitly required to sell their gas in the domestic market. Western Australia has plenty of gas, but some gas users have But they must commit to building the domestic infrastructure necessary to meet raised concerns that LNG producers will put foreign buyers first, their domestic commitments, such as processing plant and pipelines, and they must make domestic gas available from the date that exports commence. Gas and fail to meet the needs or timing of smaller local customers. swaps and negotiating access to existing infrastructure are permitted. Government of Western Australia (2006); Government of Western Australia (2012c)

Grattan Institute 2013 34 Getting gas right: Australia’s energy challenge

4.3.1 How oversupply eventually led to high prices Eventually the surplus gas led to the development of more gas- fired power generation.72 Yet low prices also helped to limit The Western Australian economy became very gas intensive as a competition in the gas market to just a few suppliers. During the result of the North West Shelf deal (Figure 20). With ample supply 1990s, the North West Shelf project supplied most domestic gas, and low prices, gas consumption rose fivefold from around 35 to with the balance coming from a small number of alternative 150 petajoules each year in the decade after the early 1980s. The producers, as Figure 21 shows. State Government paid for the gas whether it was consumed or not. It was effectively a transfer from state taxpayers to industrial Figure 21: Western Australia domestic gas production gas consumers.

Figure 20: Gas consumed per dollar of state product

Terajoules per $ million 6

5

4 WA 3

2

Vic 1 Qld NSW 0 Source: APPEA production statistics, reproduced in SKM (2011) 1990-91 1995-96 2000-01 2005-06 2010-11

Source: BREE (2012a)

72 SKM (2011)

Grattan Institute 2013 35 Getting gas right: Australia’s energy challenge

During the late-1990s and 2000s, there was very little investment abundance of gas, but the market is in transition, and the difficulty in domestic gas processing capacity in the Western Australian reflects different expectations of price, volume and contract market, as Figure 22 shows. Ample supply and low prices length. discouraged gas producers from developing new infrastructure. Lack of investment in new gas supply capacity was not a problem Figure 22: Western Australia domestic gas processing capacity, while existing capacity could adequately supply the market. But in consumption and prices the last decade several factors combined to increase demand and decrease supply. The gap between gas consumption and capacity to supply shrank to nothing and new contract prices jumped sharply (Figure 22).

From the mid-2000s, Western Australia’s minerals boom accelerated growth in domestic demand for gas. An expansion project increased the capacity of the Dampier to Bunbury pipeline, which also enabled large industrial customers to take more gas.73

At the same time, competition among suppliers shrank. Several of the smaller gas fields in the Perth and Carnarvon Basins were depleted.74 As a result, two-thirds of Western Australia’s domestic gas supply came from the North West Shelf project between 2009 and 2012. Close to a third came from Varanus Island, a separate gas processing facility in the Carnarvon Basin.

In 2011, a Western Australian parliamentary inquiry into higher gas prices found that a lack of gas processing capacity had been a major factor.75 The Inquiry also highlighted that companies were Note: Prices spiked when the NWS came online in 1984. This may reflect uncertainty about the marginal cost of production before the project was completed. struggling to agree on terms for new contracts. The state has an Source: APPEA (2010); BREE (2012a); Government of Western Australia (2012b); SKM (2011) 73 The pipeline’s owners had been in financial difficulty over about 2000-05, and the pipeline was not expanded during that period. Economics and Industry Standing Committee (2011) p36. 74 Ibid. p6 75 Ibid.

Grattan Institute 2013 36 Getting gas right: Australia’s energy challenge

4.3.2 Oversupply could happen again Pluto and Wheatstone LNG projects, both of which will supply 200 terajoules a day. The Gorgon LNG project is due to start The market did respond to higher prices, however. New supplying the domestic market with 150 terajoules a day in about processing capacity has come online at Devil Creek this year and 2015.80 a similar-sized facility is well advanced at Macedon.76 The North West Shelf is also investing, having committed $5 billion to Figure 23 illustrates the case where all LNG projects currently recover low-pressure gas from fields in the Carnarvon Basin.77 All under development build new processing facilities sufficient to are intended for the domestic market, and all were committed to in deliver 15 per cent of their output to domestic users. In this case 2008-10, after prices rose. A conservative estimate puts domestic the market would rapidly return to surplus capacity. The gas supply investments since 2008 at $7.5 billion.78 Government has implied that this would not occur, saying that it will apply the gas reservation policy flexibly, to manage supply Several new LNG facilities will start producing gas in the next few and individual project circumstances.81 But getting the right years with scope to supply domestic customers. Given the right balance between supply and demand will be difficult, and will price, there is no reason to expect they would not do so. However, always be so for any government. This is especially the case if the Government strictly applies the domestic gas reservation when government has a strong incentive to keep prices low. The policy they will have little choice. What happens next depends on problem is best left for markets to solve. how the policy is enforced. 4.4 What should government do next? In 2012, the Government’s Strategic Energy Initiative confirmed its commitment to reserving gas for the domestic market and While Western Australia has significant differences to the eastern tightened the policy’s requirements.79 So far the Government has states, the same principles apply. The Government should seek to negotiated domestic agreements under the reservation with the develop and support efficient gas market frameworks.

76 Although the gas fields they will draw on are small compared with some LNG projects, they are still expected to deliver about 400 terajoules a day at full capacity (North West Shelf has delivered 600 terajoules a day). 77 North Rankin redevelopment project. Woodside (2013) 78 Devil Creek, Macedon and North Rankin. Does not include the North West Shelf’s Greater Western Flank project (which may export), or the Gorgon, Wheatstone or Buru projects (will/may operate under the gas reservation policy). 80 The Gorgon project has its own legislation that requires domestic supply. The 79 The updated policy requires a firm 15% of output over the life of the project, as Pluto and Wheatstone agreements have been claimed as successes for the distinct from ‘up to 15%’, the wording in the 2006 policy. Added to this, domestic reservation policy, although it is plausible that they or similar projects would have supply must commence at the same time as LNG exports. Government of occurred without the policy in place. Eg DomGas Alliance (2013) Western Australia (2012c) 81 Government of Western Australia (2012c)

Grattan Institute 2013 37 Getting gas right: Australia’s energy challenge

Figure 23 Western Australia actual and projected domestic gas 4.4.1 Let the market operate consumption and gas processing capacity The Western Australian Government should end the gas reservation policy and allow the market to balance supply and demand. Forcing producers to commit to the domestic market could repeat history.

Too much supply would again push gas prices down. This might seem attractive, but artificially low prices are bad for the gas market. Artificially low prices limit competition between producers and suppress incentives to develop alternative sources of supply. In the longer-term the market would bring on new supply, but as recent experience has shown, prices would have to rise sharply. Shortages are possible.

Artificially low prices are also bad for the economy. Supporting businesses through low-priced gas might seem attractive. But it is effectively a subsidy for gas users, paid for by gas producers. Some of those users will struggle to compete when gas prices rise. The Western Australian economy would be better off

developing industries that are highly competitive. Notes: Projected domestic gas consumption is the ‘High gas supply’ scenario in ACILTasman’s modelling for the Western Australian Government (reference LNG exporters should still 'pay their dues' for access to Australia's below). Projected processing capacity assumes the following LNG projects add capacity for 15 per cent of expected output: Macedon (2014), Spar (2016), Icthys natural resources. Governments should ensure that a portion of (2016), Gorgon (2016), Wheatstone (2016), Devil Creek expansion (2017), Pluto the benefits from gas exports is shared across the community. (2018), Gorgon 2 (2021) and Browse (2021). Perth Basin fields Beharra Spings, Reserving gas is poor tool for this, because there is little scope to Dongarra-Mondarra and Woodada decline to zero by 2015. Does not include North Rankin or Buru Energy projects. target those most in need. Instead, the Commonwealth and Source: APPEA (2010); BREE (2012a); Government of Western Australia (2012b); SKM Western Australian Governments should ensure that there is an (2011); ACIL Tasman (2011) efficient tax regime in place for the gas industry, and that the gains are distributed appropriately.

Grattan Institute 2013 38 Getting gas right: Australia’s energy challenge

Choosing to end the reservation policy will involve some pain. 4.4.3 Consider a capacity market for pipeline access Gas will go to its highest-value use and, in the short-term, prices will rise to ‘export parity’ levels. Gas users will need to adjust, by Increasing access to pipeline capacity could improve competition. being more efficient, switching fuels or passing on some costs. The Dampier to Bunbury Natural Gas Pipeline ships about 90 per 84 Some businesses may not stay in the state. But in the longer-term cent of state’s gas at some point between production and use. the market will have sustainable prices, more competition and But there is no transparent mechanism to support competitive greater security of supply. short-term access to pipeline capacity. The pipeline is fully contracted to at least 2019, and the owner expands capacity only 4.4.2 Review joint marketing arrangements when it has long-term contracts for new supply.85 This constrains short-term supply that could deliver more gas onto the market. Joint marketing reduces competition in the upstream gas sector by reducing the number of sellers in the market. In 2009 and 2010 The Western Australian Government recognised the problem in the ACCC authorised joint marketing arrangements for the the Strategic Energy Initiative 2031 but only committed to Gorgon and North West Shelf projects until 2015. It argued that “encouraging the owners of major gas pipelines to consider temporarily allowing joint marketing would help to relieve pressure options for increasing the practical capacity of their infrastructure on domestic gas supplies by bringing more gas into the domestic through offering more flexible access contracts.”86 The market and avoiding delays in the Gorgon development.82 Government could go further and facilitate the development of a platform for trading pipeline capacity. Over the coming years several new projects will come online. This will increase competition and relieve some or all of the supply Pipeline capacity trading could help potential buyers and sellers to constraints on which the joint marketing authorisations were find each other and negotiate a price. This would assist in making based. If this happens, the ACCC should move toward eliminating the capacity market more competitive. Such a mechanism could joint marketing arrangements.83 Doing so would increase take a form similar to the capacity market being developed by the competition further still, a good thing for a maturing market. The Australian Energy Market Operator on the east coast. fact that smaller projects in Western Australia have been able to market their gas separately suggests that joint marketing is not 84 Economics and Industry Standing Committee (2011) essential for larger gas producers. 85 In 2004, the Dampier Bunbury Pipeline negotiated the right to charge a higher price for pipeline access than regulation would normally allow. The deal was done outside of the regulatory regime to get the pipeline out of administration. Adding spare capacity on the pipeline now would push prices down. Access 82 ACCC (2009); ACCC (2010) would be at a lower regulated price and that would, under the terms of the 83 Joint-marketing authorisation might be retained for companies with a very negotiated standard shipper contract, flow on to all other shippers ibid. p139 small stake in a joint venture. 86 Government of Western Australia (2012c)

Grattan Institute 2013 39 Getting gas right: Australia’s energy challenge

5. Carbon emissions and gas-fired power generation

About a third of the gas consumed in the Australian economy is Figure 24: Required electricity price to justify new fossil fuel power used to generate electricity. Once converted to electricity, gas- plant construction, at various carbon prices 87 fired generation supplies about 19 per cent of our power. The $ per megawatt-hour rest is generated from black coal (46 per cent), brown coal (22 per 140 cent), renewable energy (10 per cent) and oil and other fuels Brown coal (2 per cent). 120 $6/t In 2010 the Australian Bureau of Agricultural and Resource Black coal 100 $40/t Economics predicted that gas-fired generation was about to 88 increase rapidly. The growth would be driven by several factors: 80 Gas cheap gas, a carbon price that would make coal generation more $6/GJ expensive than gas, and increased demand for electricity due to 60 population growth and higher levels of energy consumption. 40 Figure 24 explains why gas would have been favoured to meet new demand, even with a relatively modest carbon price. It shows 20 the cost of electricity that new fossil-fuel power plants would require at different carbon prices. 0 0102030405060 Carbon price $/t Unlike renewable energy sources such as solar and wind, gas- fired power stations produce carbon emissions. Yet for each unit of electricity produced, a new gas-fired power station will produce Source: Grattan Analysis about half the emissions of a black coal power plant and a third of those of a brown coal power station. Despite these advantages, the ‘dash for gas’ isn’t happening. There are three reasons why. Electricity demand has been falling, rather than growing. Second, since about 2008, legislation to support renewable energy is forcing additional renewable energy into this shrinking market. Third, higher gas prices rule out 87 BREE (2012a) switching from existing coal to existing gas power stations. 88 Syed, et al. (2010)

Grattan Institute 2013 40 Getting gas right: Australia’s energy challenge

The change has important implications for policy makers. It has Figure 25: Electricity demand forecasts for eastern Australia, 2006 particular implications for how we reduce emissions of carbon to 2017 dioxide in coming years, and for managing the longer-term Terawatt-hours process of transforming our power generation infrastructure to use 215 less carbon-intensive fuels. Actual Forecast Fast growth 210 5.1 Falling demand means no new capacity is needed 205 Planning Electricity demand forecasts from as recently as late last decade showed steady growth well into the current decade. Yet since 200 2008 demand has fallen, as Figure 25 shows. This is due to a 195 number of factors, including reduced demand across all sectors Slow growth as higher electricity prices bite, lower manufacturing output, and 190 the rapid uptake of solar PV systems, driven by state-based support policies. 185 180 Figure 25 also shows the most recent published forecasts for electricity demand under a range of scenarios. Data collected 175 since these forecasts were published suggest the falling trend is 2006 2008 2010 2012 2014 2016 continuing and that electricity demand will be at the lower end of the forecast range. The prospects for new gas-fired power stations look very poor for at least a decade. Source: AEMO (2012b)

5.2 Gas is not the cheapest option In the wholesale electricity market, output from power plants is adjusted continuously to ensure that supply meets demand. Higher gas prices will also result in existing gas-fired generators During periods of high electricity demand, prices rise and power operating less often. Figure 26 illustrates why. With low gas prices stations produce more. The analysis in Figure 26 does not mean and a carbon price of at least $30 a tonne of carbon dioxide, that the plants with higher costs will cease to operate entirely. existing gas fired generators are cheaper to operate than black or However, power stations that face higher operating costs are brown coal-fired generators. However, with high gas prices and likely to run less often. low carbon prices brown coal provides the cheapest electricity, followed by black coal.

Grattan Institute 2013 41 Getting gas right: Australia’s energy challenge

Figure 26: Required electricity price to justify running fossil fuel 20 per cent of their electricity from renewable energy sources by power plants, at various carbon prices 2020. The result of the policy has been rapid deployment of wind- $ per megawatt-hour powered electricity. This has reduced demand for other types of generation, including gas-fired power. 90 Gas $8/GJ 80 5.4 The future for gas-fired generation is uncertain Brown coal 70 $6/t Black coal The future of gas-fired generation in Australia is highly uncertain. 60 $40/t Figure 27 shows a recent forecast for demand for gas-fired Gas generation in eastern Australia. The Planning Scenario is based 50 $4/GJ on medium economic growth, stable coal prices and the current 40 emissions reduction target of 5 per cent below 2000 levels by 2020. The Slow Change Scenario is based on slower economic 30 growth, falling coal prices and an effective collapse in the carbon 20 price.

10 Future developments could reignite the ‘dash for gas’ in Australia. 0 These developments could include a return to electricity demand 0102030405060 growth, stronger and more secure targets under climate change Carbon price $/t policies, lower gas prices or a major reduction in the Renewable Source: Grattan analysis Energy Target. In the absence of such changes, the low- emissions potential of gas will remain unfulfilled in Australia. The ability of black or brown coal power to substitute for gas-fired power in most circumstances may be good news for electricity 5.5 Global gas demand will be linked to carbon policies customers. It means that higher gas prices are unlikely to substantially increase electricity prices. But it is not good news for Globally, fossil fuels are far from finished. Unconventional carbon emission levels. extraction methods have replenished global reserves of oil, gas and other fuels that have the potential to produce a large amount 5.3 Renewable energy is favoured under current policies of carbon emissions. Concerns about “peak oil” – where prices rise rapidly as all available oil reserves are depleted - have Gas-fired generation has also been affected by the Renewable receded and global gas resources could supply current demand Energy Target, which requires energy retailers to buy more than

Grattan Institute 2013 42 Getting gas right: Australia’s energy challenge

for over 200 years.89 These developments may take the world into emissions will increase. Low-cost, gas-fired generation may even a new phase of abundant fossil fuel supplies.90 mean less investment in renewable energy. It is unclear what the net result for carbon emissions will be. Figure 27: Outlook for gas demand for electricity generation in eastern Australia, 2008 to 2032 While the Australian ‘dash for gas’ is not occurring, the global story is different. In the US, low shale gas prices have triggered a Petajoules per year shift away from coal and towards gas-fired power generation. This 300 has helped to reduce US greenhouse gas emissions.91 Planning scenario

250 Actual gas-fired In Japan, nuclear power stations were closed following a 2011 power generation nuclear disaster. As a result, demand for gas-fired power 200 generation has risen, despite higher gas prices. Whether this continues will depend on global action towards reducing carbon emissions. 150 Figure 28 shows the range of forecasts for global gas demand 100 developed by the International Energy Agency. The three Slow rate of change scenarios feature different assumptions about global action to scenario address climate change.92 Current international climate 50 negotiations aim to limit average global temperature increases to two degrees centigrade.93 Under this scenario, global growth in 0 gas demand would peak and flatten by about 2030. 2008 2012 2016 2020 2024 2028 2032

Source: AEMO (2012a)

While this is good news for a rapidly developing, energy-hungry world, it could be very bad news for global climate change policy. Where gas replaces coal-fired power generation, it will lower global carbon emissions. Where it replaces nuclear energy, 91 EPA (2013); EIA (2011) 89 IEA (2012) 92 IEA (2012) 90 Helm (2013); Carbon Tracker Initiative (2013) 93 World Bank (2012)

Grattan Institute 2013 43 Getting gas right: Australia’s energy challenge

Figure 28: World natural gas demand under different carbon policy scenarios, 1990 to 2035

Exajoules per year 200 Current policies

175 New policies

150 450 ppm scenario 125

100

75

50 1990 1995 2000 2005 2010 2015 2020 2025 2030 2035

Source: IEA (2012)

The role of gas-fired generation in meeting future global energy demand will depend on the development of affordable carbon capture and storage technology that can be used alongside gas fired generators. At present it is unclear whether the technology can be implemented in an affordable, reliable manner. If it can, gas-fired generation may continue to grow strongly, even in a carbon-constrained world.

Grattan Institute 2013 44 Getting gas right: Australia’s energy challenge

6. References

ABS (2010) 5209.0.55.001 - Australian National Accounts: Input-Output Tables - ACIL Tasman (2011) Energy futures for Western Australia - Scenario Electronic Publication, Final release 2006-07 tables, Input Output development and modelling outcomes Prepared for the Office of Energy Multipliers, accessed 16 June 2013, from ACIL Tasman (2012) Fuel Cost Projections, Updated natural gas and coal http://www.abs.gov.au/AUSSTATS/[email protected]/Previousproducts/5209.0. outlook for AEMO modelling, accessed 16 June 2013, from 55.001Main Features4Final release 2006-07 http://www.google.com.au/url?sa=t&rct=j&q=&esrc=s&frm=1&source=w tables?opendocument&tabname=Summary&prodno=5209.0.55.001&is eb&cd=1&ved=0CCoQFjAA&url=http%3A%2F%2Fwww.aemo.com.au sue=Final release 2006-07 tables&num=&view %2FConsultations%2FNational-Electricity- ABS (2011a) 4442.0 - Family Characteristics, Australia, 2009-10 Households, Market%2FOpen%2F~%2Fmedia%2FFiles%2FOther%2Fplanning%2F families and persons, Selected characteristics, 1997, 2003, 2006–07, Fuel_cost_projections_Natural_gas_and_coal_outlooks.ashx&ei=6Pum 2009–10 accessed 16 June 2013, from UZ- http://www.abs.gov.au/AUSSTATS/[email protected]/DetailsPage/4442.02009- eGYfbkQWEioDgDQ&usg=AFQjCNGR2ah8mGOLHL8XJmqv9DWsNQ 10?OpenDocument iZTg&sig2=HjzPSbOztzz8HKqfIGMtPg ABS (2011b) 6530.0 - Household Expenditure Survey, Australia: Summary of AEMO (2011) Gas Statement of Opportunities, Australian Energy Market Results, 2009-10, HES 2009–10 Detailed tables, accessed 16 June Operator 2013, from AEMO (2012a) Gas Statement of Opportunities, Australian Energy Market http://www.abs.gov.au/AUSSTATS/[email protected]/DetailsPage/6530.02009- Operator 10?OpenDocument AEMO (2012b) National Electricity Forecasting Report, Australian Energy Market ACCC (2009) Determination: Applications for authorisation lodged by Chevron Operator Australia Pty Ltd, Chevron (TAPL) Pty Ltd, Mobil Australia Resources AEMO (2012c) Victorian Gas System Adequacy, Australian Energy Market Company Pty Ltd and Shell Development (Australia) Pty Ltd in respect Operator of the joint marketing and sale of natural gas from the Gorgon Gas AEMO (2013) 'Development Work', accessed 16 June 2013, from Project for supply in Western Australia, C2009/979, Australian http://www.aemo.com.au/Gas/Market-Operations/Gas-Supply- Competition and Consumer Commission Hub/Development-Work ACCC (2010) Determination: Applications for authorisation lodged by BHP AER (2006) State of the Energy Market, Australian Energy Regulator Billiton Petroleum (North West Shelf) Pty Ltd, BP Developments AER (2007) State of the Energy Market, Australian Energy Regulator Australia Pty Ltd, Chevron Australia Pty Ltd, Japan Australia LNG AER (2008) State of the Energy Market, Australian Energy Regulator (MIMI) Pty Ltd, Shell Development (Australia) Pty Ltd and Woodside AER (2009) State of the Energy Market, Australian Energy Regulator Energy Ltd in respect of the joint marketing activities for the sale of AER (2010) State of the Energy Market, Australian Energy Regulator domgas in Western Australia from the North West Shelf Project and to AER (2011) State of the Energy Market, Australian Energy Regulator administer existing gas supply contracts, C2010/344, Australian AER (2012) State of the Energy Market, Australian Energy Regulator Competition and Consumer Commission AIG (2013a) AIG Energy Stakeholder Survey, ACIL Tasman (2010) Gas prices in Western Australia, Review of inputs to the AIG (2013b) 'Manufacturing malaise continues', accessed 16 June 2013, from WA Wholesale Energy Market, accessed 16 June 2013, from http://www.aigroup.com.au/industrynewsletter - Box1 http://www.imowa.com.au/f2138,484255/484255_ACIL_Tasman_Final_ APLNG (2013) 'Project partners', accessed April 2013, from Report_-_Updated.pdf http://www.aplng.com.au/about-project/project-partners

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